PIPELINES & DOWNSTREAM Alyeska cyber-aware
Transcript of PIPELINES & DOWNSTREAM Alyeska cyber-aware
US crude approaches 11 million bpd in April; $65 Brent 2nd qtr average
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l P I P E L I N E S & D O W N S T R E A M
l N A T U R A L G A S
Vol. 26, No. 20 • www.PetroleumNews.com A weekly oil & gas newspaper based in Anchorage, Alaska Week of May 16, 2021 • $2.50
l E X P L O R A T I O N & P R O D U C T I O N
see OIL PRICES page 12
see ANGOON TIDAL page 11
Company applies to FERC for Angoon tidal power evaluation
Littoral Power Systems Inc. has applied to the Federal Energy
Regulatory Commission for a preliminary permit for a tidal
power project at Kootznahoo Inlet near Angoon on Admiralty
Island in Southeast Alaska.
This is one of two preliminary tidal power permit applications
in Alaska that FERC is considering — this small project and a
much larger one in Cook Inlet.
A preliminary permit, if issued, grants the permit holder prior-
ity to file a license application during the permit term.
Littoral Power Systems, LPS, said the preliminary permit
would allow it to “evaluate the potential for generating electricity
from tidal energy in Kootznahoo Inlet in Angoon, Alaska.”
Hummingbird nesting season stops TMX pipeline expansion
Canada’s Trans Mountain pipeline expansion has never
escaped the battlefront from the time of the project’s public
launch in 2012.
Building a 710-mile link to triple capacity on the system to
890,000 barrels per day of crude bitumen from the Alberta oil
sands, through the Canadian Rockies to a Vancouver area tanker
terminal, primarily for export to Asian markets was never going
to be easy.
As opposition to what is known as TMX has stretched the
completion date for the C$12.6 billion undertaking to late 2022,
environmentalists, First Nations and all-purpose protesters have
drawn strength from their occasional success in stalling work on
the pipeline.
see PIPELINE EXPANSION page 10
see DRILLING RULES page 9
Oil prices hit 8-week high May 12; Q3, Q4 demand acceleration seen
Alaska North Slope crude rose 37 cents to close at $67.85 per
barrel May 12, while West Texas International rose 80 cents to
close at $66.08 and Brent rose 77 cents to close at $69.32.
It was the highest close for WTI since March 5, and the high-
est close for Brent since March 11.
In early trading, Brent once again made a run at $70, rising to
$69.79 before dropping later in the day as Colonial Pipeline
restarted its 5,500-mile fuel line from Texas to the East Coast
after a precautionary shutdown spurred by a cyberattack discov-
ered May 7.
U.S. Energy Secretary Jennifer Granholm said in a May 11
briefing that it would “take days” after the restart for the line to
be “up and running.”
“This pipeline has never been shut down before,” she said.
Alyeska cyber-aware TAPS secure, but operator has close eye on Colonial Pipeline cyber attack
By STEVE SUTHERLIN Petroleum News
Alyeska Pipeline Service Co. maintains a state of
readiness when it comes to cyberthreats.
Just like any other operating risk of running the
800-mile Trans Alaska Pipeline System, cyber risk
is on the front burner 24/7 at Alyeska, according to
Michelle Egan, Alyeska chief communications
officer.
“We have a very comprehensive cybersecurity
program here — it involves multiple layers of protec-
tion; we have an in-house cybersecurity team; we
have a number of third-party experts and vendors that
we work with; and we have very regular engagement
with law enforcement agencies around this area — so
that we’re aware of what is happening in the world of
cyber security, Egan told Petroleum News in a May
11 interview.
The operator of TAPS is watching closely the sit-
uation at Colonial Pipeline Co. where a 5,500-mile
fuel pipeline was shut down by a cyber-attack discov-
ered May 7, choking off vital fossil fuel supplies to
Borealis moves forward Independent continues permitting 2022 Nanushuk exploratory drilling program
By KAY CASHMAN Petroleum News
In preparation for exploratory drilling
next winter in its Castle North prospect
in the northeastern National Petroleum
Reserve-Alaska, Borealis Alaska Oil Inc.
applied for an Oil Discharge Prevention
and Contingency Plan with the Alaska
Department of Environmental
Conservation. That plan, which is compre-
hensive and covers the company’s explo-
ration drilling operations for all its NPR-A North
Slope oil and gas prospects, is out for a 30-day public
review that ends June 7 at 11:59 p.m. AKT.
In NPR-A, the Borealis leases lie in what the
Anchorage-based independent named the Castle
prospect trend, a series of six individual
Brookian prospects in the lower Nanushuk
formation. Southwest of Willow, the
prospects are directly analogous to the geo-
logic setting for major oil discoveries at
Pikka, under development by Oil Search
(Alaska), and by ConocoPhillips at Willow,
Richard “Dick” Garrard, Borealis chief
technical officer, told Petroleum News in
mid-2020.
Borealis’ Castle East prospect lies in the
same sand body as the Harpoon prospect,
where ConocoPhillips drilled an exploration well in
the winter of 2019-20.
Borealis is looking for a joint venture partner for
BP underpins Woodfibre Doubles take from planned LNG project; First Nations splinter group gets BC cash
By GARY PARK Petroleum News
Canada’s often-overlooked Woodfibre LNG
project has received a large helping hand
from BP which has now signed a second deal to
take output from the proposed export plant near
Vancouver.
Woodfibre said it will sell 750,000 metric tons
a year to BP Gas Marketing over 15 years, dou-
bling BP’s total off-take to 1.5 million mt from the
planned initial plant capacity of 2.1 million mt.
The deal is seen as an important advance for the
C$1.8 billion project as sets a final investment
decision in the third quarter by its owner, Pacific
Oil & Gas.
A Woodfibre spokeswoman said the company is
now seeking contracts for the remaining 29% of
annual capacity but will not make those deals a
mandatory element of its decision to proceed with
construction.
She said Woodfibre is engaged in final engi-
neering work while attempting to revise its envi-
ronmental permit to allow floating accommodation
for up to 600 workers during construction.
see CYBER-AWARE page 10
see BOREALIS PERMITTING page 8
see WOODFIBRE LNG page 11
“We learn things and change things because that’s part of this world of
cybersecurity, it’s continually moving … a very dynamic area.” —Michelle Egan, Alyeska chief communications officer
RICHARD “DICK” GARRARD
On the positive side, global LNG demand has increased every year since 2012,
propelled by fast-rising demand in Asia.
Moriarty: Interior scraps Trump’s new Arctic safety, enviro updates
In the current administration’s “eager-
ness” to do away with Trump’s policies,
politics have dictated what should be a
scientific process, Kara Moriarty told
Petroleum News regarding the U.S.
Interior Department May 7 decision not to
pursue the former administration’s pro-
posal for changes in Arctic drilling rules
offshore Alaska.
A May 7 statement from Interior said
existing regulations released by the
Obama administration in 2016 remain in effect and “are critical
KARA MORIARTY
2 PETROLEUM NEWS • WEEK OF MAY 16, 2021
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2-9469
MEA PLANT
YELLYY..
Petroleum News Alaska’s source for oil and gas newscontentsAlyeska cyber-aware TAPS secure, but operator has close eye on latest cyber attack
Borealis moves forward Continues permitting 2022 Nanushuk exploratory drilling program
BP underpins Woodfibre Doubles take from LNG project; First Nations group gets BC cash
ON THE COVER
Oil prices hit 8-week high May 12; Q3, Q4 demand acceleration seen
Moriarty: Interior scraps Trump’s new Arctic safety, enviro updatesCompany applies to FERC for Angoon tidal power evaluationHummingbird nesting season stops TMX pipeline expansion
EXPLORERS 2021 PREVIEW4 ConocoPhillips: ‘hitting reset’ in 2021
Alaska’s most consistent explorer resumes activities at several projects; 700 people on GMT-2 project’s third winter of work
3 US crude almost 11 million bpd in April
EIA expects Brent to average $65 per barrel in 2nd quarter, $61 in 2nd half of year and in 2022, with WTI above $55 through 2022
2 Division approves Prudhoe ops amendments
8 Weekly US rotary rig count up by 8 to 448
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l E X P L O R A T I O N & P R O D U C T I O N
Division approves Prudhoe ops amendments By KRISTEN NELSON
Petroleum News
The Alaska Division of Oil and Gas has approved
requests from Hilcorp North Slope for three projects
as amendments to the Prudhoe Bay unit operations plan.
The most recent, dated May 10, is for authorization to
construct a temporary polymer injection facility at W Pad
at Prudhoe. The purpose is to inject polymer in W Pad
wells to increase production. W Pad is some 17 miles
northwest of Deadhorse.
The division said the temporary facility will consist of
several modules to be placed centrally on the pad. The
temporary facility is estimated to be in place for about
one year, with the project planned to start in June and
conclude by December.
Included in the plan are:
•Leveling the existing pad to prepare for module
installation;
•Place rig mats and insulation to support skids;
•Installing a water let down module, 20 feet by 8 feet;
•Installing a polymer hydration module 40 feet by 8
feet;
•Installing a polymer injection pump module 40 feet
by 8 feet;
•Installing a polymer loading and storage module 40
feet by 8 feet:
•Installing some 2,500 feet of 2-inch polymer injection
piping on existing pipe racks; and
•Tying modules to existing aboveground facilities
including power and water.
Pigging shelter Also at W Pad at Prudhoe, the division on May 6
approved a request to install a pig shelter, a 32- by 20-foot
shelter on a steel frame over existing pipelines on the
western side of the pad.
The division said the purpose is to provide a shelter for
pig-launching operations on W Pad, with the project
expected to begin June 1 and be completed by December.
Plan activities include:
•Installing steel foundation bracing and VersaTube
framing;
•Constructing the 32- by 20-foot pigging shelter;
•Installing associating piping and values; and
•Installing a safety guardrail.
In the first quarter of the year, W Pad accounted for
some 4% of Prudhoe crude oil production, up from 3.2%
in the first quarter of 2018.
Main Construction Camp On May 6 the division approved a Hilcorp request to
see PRUDHOE OPS page 3
By KRISTEN NELSON Petroleum News
In its May Short-Term Energy Outlook,
issued May 11, the U.S. Energy
Information Administration said U.S. crude
oil production continues to rise.
While the most recent data, for February,
shows a drop, to 9.9 million barrels per day,
down 1.2 million bpd from January, EIA
said it believes that is an anomaly.
The agency is estimating that U.S. crude
production rose to 10.9 million bpd in
March and to almost 11 million bpd in
April.
The February decline was caused by
cold temperatures, EIA said, which caused
significant declines in Texas production and
smaller declines in other states, with pro-
duction outages estimated to be largely lim-
ited to February.
The agency expects the West Texas
Intermediate price will stay in a range to
encourage drilling.
“We estimate that U.S. benchmark West
Texas Intermediate crude oil prices will
remain above $55 per barrel through 2022,”
EIA Acting Administrator Steve Nalley said
in a statement. “This benchmark price will
likely encourage producers to drill and
complete wells and to offset production
declines at existing wells, and that activity
along with our forecast for rising produc-
tion from multiple new projects in the
Federal Offshore Gulf of Mexico, leads us
to believe U.S. crude oil production will
average 11.3 million barrels per day in the
fourth quarter of 2021 and 11.8 million bar-
rels per day in 2022.”
EIA said the spread between Brent and
WTI has been increasing since November,
with weather events in the U.S. appearing to
play a role along with rising U.S. crude oil
production. From a narrow average spread
of $1.68 per barrel in October, the lowest
point since the pandemic began, the spread
has widened each month, averaging $3.38
per barrel in March and $3.63 per barrel in
April.
Brent steady Brent prices averaged $65 per barrel in
April, EIA said,
unchanged from the
March average.
“Brent crude oil
prices remained at
$65 per barrel in
April as COVID-19
continued to affect
demand in major
economies,” Nalley
said. “U.S. oil
demand is increasing along with COVID-
19 vaccination rates and overall econom-
ic activity, but India’s oil demand is
declining due to rising COVID-19 cases,”
he said.
The agency is forecasting that Brent
will average $65 per barrel in the second
quarter, $61 per barrel in the second half
of the year and $61 per barrel in 2022.
World consumption EIA said it estimates that worldwide
96.2 million bpd of petroleum and liquid
fuels were consumed in April, up 15.8
million bpd from April 2020 but down 4
million bpd from 2019 levels.
Nalley said EIA has lowered its esti-
mates for global consumption based on
“lower economic growth estimates and
decreased demand for transportation fuels
in India.” Global consumption for 2021 is
now estimated to average 97.7 million
bpd, he said, “an increase of 5.4 million
barrels per day over 2020.”
EIA said the estimate for global petro-
leum and liquid fuels consumption is an
average of 101.4 million bpd in 2022, an
increase of 3.7 million bpd.
Natural gas The Henry Hub spot price for natural
gas averaged $2.66 per million British
thermal units in April, up slightly from a
March average of $2.62 per million Btu,
EIA said. The price is expected to average
$2.78 per million Btu in the second quar-
ter, and $3.05 for the year, up from the
2020 average of $2.03 per million Btu.
Two factors are expected to drive the
rise in natural gas prices, the agency said
— growth in liquefied natural gas exports
and rising domestic consumption in the
residential, commercial and industrial
sectors.
The Henry Hub spot price is expected
to fall to an average of $3.02 per million
Btu in 2022, with LNG exports expected
to slow and production expected to rise.
“U.S. liquefied natural gas exports set
an all-time record in March 2021,”
Nalley said, “averaging 10.5 billion cubic
feet per day, followed by an April average
of 9.2 billion cubic feet per day, the most
liquefied natural gas exported from the
United States during April since the
United States began exporting liquefied
natural gas.”
EIA said that in 2020 and January
2021, “more than half of U.S. LNG
exports went to Asia. However, in
February and March 2021, more than half
of U.S. LNG exports went to Europe as a
result of spot natural gas prices in Europe
reaching levels similar to spot natural gas
prices in Asia.”
The agency said it expects LNG
exports to decline in May to 8.6 bcf per
day before rising above 9 bcf per day in
the summer months to meet peak
demand, with exports expected to aver-
age 9.2 bcf per day in both 2021 and
2022, up from 6.5 bcf in 2020, with flat
exports in 2022 reflecting the agency’s
expectation “that limited new expert
capacity will come online during the fore-
cast period.”
U.S. consumption of natural gas is
expected to average 82.6 bcf per day this
year, down 0.7% from 2020, declining in
the forecast to 82.5 bcf per day in 2021,
with the decline attributed, in part, to
electric power generators switching to
coal as a result of rising natural gas
prices.
Outside the power sector, consump-
tion is expected to rise due to expanding
economic activity and colder tempera-
tures in 2021 compared to 2020.
More electricity from renewables “Our forecast increase in electricity
generation from renewable sources is
especially pronounced in Texas, where
we expect renewables to generate about
30% more electricity this summer than
last summer,” Nalley said.
EIA said planned additions to U.S.
PETROLEUM NEWS • WEEK OF MAY 16, 2021 3
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Regulations are changing constantly. For the most up-to-date inform
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install a new aboveground water
tank at the Main Construction Camp
at Prudhoe. The division said the
existing water tank subsided over
time and is no longer suitable as the
main tank for the MCC fire suppres-
sion system.
The new site will be excavated
and a foundation constructed to hold
the tank, which will be tied in to the
existing tank. The existing tank will
remain in place and minimal
changes will be required in the pip-
ing layout. Work is expected to start
in June and be complete by the end
of the year, the division said.
Plan activities include:
•Constructing the foundation for
the new tank; and
•Installing the new 370,000-gal-
lon water tank. l
continued from page 2
PRUDHOE OPS
l F I N A N C E & E C O N O M Y
US crude almost 11 million bpd in April EIA expects Brent to average $65 per barrel in 2nd quarter, $61 in 2nd half of year and in 2022, with WTI above $55 through 2022
STEVE NALLEY
see EIA OUTLOOK page 7
By ERIC LIDJI For Petroleum News
ConocoPhillips Alaska Inc. is the most
prolific North Slope explorer of the
21st century.
As many of its large multinational
contemporaries were retreating from
exploration to focus on development,
ConocoPhillips continued to pursue
opportunities beyond its existing North
Slope units. And although many smaller
independents occasionally outdid
ConocoPhillips in any given exploration
season, they have all lacked
ConocoPhillips’ longevity, either leaving
after a few seasons or selling prospects
after de-risking them.
In the 19 years since the 2002 merger
that created ConocoPhillips, the Alaska
unit of the Houston-based multinational
exploration and production company has
diligently pushed westward beyond the
Kuparuk River unit. Its exploration activ-
ity has now expanded the reach of North
Slope oil develop-
ment beyond the
Colville River and
into federal lands.
But for a compa-
ny defined by its
constancy and con-
sistency, the past
few years have been
unpredictable. Some
seasons were among
ConocoPhillips’ most active ever. Others
saw no exploration at all. Others started
out strong but then were unexpectedly cut
short.
ConocoPhillips conducted no explo-
ration activities this year, following two
robust winters. In the winter season of
2018-19, the company completed nine
wells listed as “exploratory” by the
Alaska Oil and Gas Conservation
Commission. The list included one well
in the Kuparuk River unit and two wells
within the Colville River unit, in addition
to six traditional exploration wells in the
National Petroleum Reserve-Alaska.
The company planned a seven-well
exploration program for 2020 but only
completed three before reducing its activ-
ities in response to the emerging coron-
avirus pandemic.
This year, the company delayed its
decision to restart drilling activity pend-
ing the results of the Nov. 3 ballot initia-
tive to increase oil production taxes in the
state. Following the defeat of the ballot
measure, and then the stabilization of oil
prices around $40 per barrel,
ConocoPhillips announced plans to
resume drilling before the end of 2020.
The announcement covered a range of
development and maintenance projects at
the Kuparuk River unit, the Colville
River unit and the Greater Mooses Tooth
unit. But it did not include any explo-
ration drilling for the 2020-21 season,
making this year one of only a handful of
exploration seasons over the past 20 years
without ConocoPhillips.
The starts and stops of the past few
years can make it easy to overlook the
larger trend: ConocoPhillips has been
undertaking a notable expansion of its
exploration activities. In addition to its
long-standing movement to the west, it
has also been pursing emerging opportu-
nities closer to its existing units at the
western edge of the central North Slope.
In a presentation at Meet Alaska in late
March 2021, ConocoPhillips Alaska
President Erec Isaacson described 2021
as “hitting reset.” The company would
focus on lowering costs and engaging
stakeholders and would also resume reg-
ular development drilling, as well as
progress on $1.1 billion in projects across
the North Slope: Greater Mooses Tooth
No. 2 construction, Alpine expansion,
Willow permitting, Nuna development
and ongoing work at the Eastern NEWS
(North East West Sak) at the Kuparuk
River unit.
Heading west ConocoPhillips is best known for its
gradual westward expansion on the North
Slope.
Through its predecessor companies,
ConocoPhillips helped discover or devel-
op the Kuparuk River unit, as well as the
Alpine field and its satellites at the
Colville River unit.
After the National Petroleum Reserve-
Alaska was reopened for exploration in
1999, ConocoPhillips’ predecessor
Phillips Petroleum Co. was one of the
first companies to explore the region. In
May 2001, Phillips announced three
major NPR-A discoveries.
“These discoveries mark an important
milestone in the Alaska oil industry,”
then-president of Phillips Alaska Kevin
Meyers said at the time. “Though the
results are preliminary, we’re confident
the discoveries will prove to be of com-
mercial quantities.”
Anyone who follows the announce-
ments of oil and gas companies knows to
be mindful of hyperbole, but
ConocoPhillips has long since justified
those comments. The company has spent
the last 20 years pursuing the NPR-A dis-
coveries announced by its predecessor in
May 2001, and it is only recently seeing
oil production from the first of those
properties.
The current push dates to 2008. That
year, ConocoPhillips formed the Greater
Mooses Tooth unit around the cluster of
NPR-A wells and discoveries west of
Nuiqsut. The move helped protect soon-
to-be-expiring leases dating back to the
original 1999 lease sale.
ConocoPhillips also relinquished 19
federal tracts around Intrepid 2 well south
of Barrow, a sign that it was losing inter-
est in wildcat exploration on the North
Slope.
Between 2008 and 2016,
ConocoPhillips gradually backed away
from Alaska offshore exploration, too.
The company dropped most of its
Beaufort Sea leases in 2009 and spent
several years pursuing Chukchi Sea
opportunities before dropping those leas-
es in 2016.
At the same time, ConocoPhillips was
increasingly focusing its energies on
exploration opportunities within close
reach of its existing onshore infrastruc-
ture. Toward the end of 2015,
ConocoPhillips CEO Ryan Lance
announced, “Over the past couple of
years, we’ve been able to change the pro-
file of our Alaska business. We’ve trans-
formed the declining production base into
one that can deliver stable production for
a decade.”
The U.S. Bureau of Land Management
approved the formation of the Greater
Mooses Tooth unit in 2008.
ConocoPhillips expanded on its May
2001 discoveries in the unit area with a
series of related exploration wells,
including the Pioneer No. 1 and
Grandview No. 1 wells in early 2009 and
the Rendezvous No. 3 and Flat Top No. 1
wells in early 2014.
Through subsequent exploration,
appraisal and development work,
ConocoPhillips unofficially divided
Greater Mooses Tooth into three regions:
east, central and west.
ConocoPhillips began producing the
eastern leases in October 2018, when it
brought the GMT-1 pad online. The com-
pany is currently in the final stages of
development work on the GMT-2 pad,
which will develop the leases in the
southcentral portion of the unit.
The company employed as many as
700 people on the GMT-2 project this
winter, which was the third and final year
of construction on the $1.4 billion proj-
ect. Development drilling on the first of
l E X P L O R E R S M A G A Z I N E P R E V I E W
ConocoPhillips: ‘hitting reset’ in 2021 Alaska’s most consistent explorer resumes activities at several projects; 700 people on GMT-2 project’s third winter of construction
4 PETROLEUM NEWS • WEEK OF MAY 16, 2021
ADDRESS P.O. Box 231647 Anchorage, AK 99523-1647 NEWS 907.522.9469 [email protected] CIRCULATION 907.522.9469 [email protected] ADVERTISING Susan Crane • 907.770.5592 [email protected]
OWNER: Petroleum Newspapers of Alaska LLC (PNA) Petroleum News (ISSN 1544-3612) • Vol. 26, No. 20 • Week of May 16, 2021
Published weekly. Address: 5441 Old Seward, #3, Anchorage, AK 99518 (Please mail ALL correspondence to:
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36 wells was scheduled to begin in the
second quarter with first oil by the end of
the year. GMT-2 should produce 35,000
to 40,000 barrels per day at its peak.
Willow Exploration activity in recent years has
focused on the western leases. Those leas-
es are now associated with the Bear Tooth
unit, which is adjacent to Greater Mooses
Tooth.
ConocoPhillips began staking its first
Tinmiaq wells in late 2015 and completed
a two-well drilling program in the area in
early 2016. The work was notable for
pushing beyond previous drilling activity
in the region. Way back in May 2001,
when Phillips Alaska Inc. announced its
initial oil discoveries in the area, the
exploration activity was clustered in what
would later become the center of the
Greater Mooses Tooth unit. Subsequent
exploration activity pushed to the south
and the east — but not into the western
leases.
The initial Tinmiaq exploration pro-
gram came as ConocoPhillips was sanc-
tioning its initial $900 million GMT-1
development at the eastern end of Greater
Mooses Tooth and permitting its GMT-2
development on leases in the south-cen-
tral section of the unit.
In early 2017, ConocoPhillips
announced that the first Tinmiaq wells —
Tinmiaq No. 2 and Tinmiaq No. 6 — had
made a major discovery in the Nanushuk
formation. The Willow prospect was esti-
mated to contain as much as 300 million
barrels of recoverable oil and could
potentially produce as much as 100,000
barrels per day at its peak.
“This discovery is tremendously excit-
ing not only for ConocoPhillips, but also
for the state of Alaska,” then-
ConocoPhillips Alaska President Joe
Marushack said. “Willow’s proximity to
existing infrastructure improves the eco-
nomic viability of the discovery.
Development of Willow, a potential
multi-billion-dollar investment, could
provide thousands of jobs during con-
struction and could generate substantial
revenue for the federal government, state,
North Slope Borough, and communities
in the NPR-A.”
In addition to being encouraged by
resource estimates, ConocoPhillips was
intrigued by Willow’s geology. Willow
was one of three major North Slope oil
discoveries made within a year in the
Nanushuk formation or in the closely
associated Torok formation — following
Armstrong Energy’s Pikka and Caelus
Energy’s Tulimaniq discoveries.
In late 2016, after drilling the two
Tinmiaq wells but before announcing the
discovery, ConocoPhillips acquired 65
tracts covering 594,972 acres in a federal
lease sale and 74 tracts covering 142,280
acres in a nearby state lease sale. And in
2017, after announcing the discovery,
ConocoPhillips commissioned a 3D seis-
mic survey over the region.
That may seem like a rush of activity,
but subsequent permitting documents
suggested that ConocoPhillips had dis-
covered the Willow prospect in 2002 with
its Hunter A well.
ConocoPhillips returned with a four-
well program in 2018 (Tinmiaq No. 7,
No. 8 and No. 9 and West Willow No. 1)
and a five-well program in 2019 (Tinmiaq
No. 10, No. 11, No. 13, No. 15 and No.
16, along with re-entry projects on
Tinmiaq No. 2 and Tinmiaq No. 9). The
company planned a six-well program in
2020 but was only able to complete two
wells (Tinmiaq No. 18 and No. 20) before
coronavirus restrictions interceded.
One of the big questions hanging over
the Willow prospect from the beginning
was whether ConocoPhillips would
develop it independently or as an Alpine
satellite. The decision would impact the
cost and design of the project, as well as
its production rate.
A satellite would produce about 40%
to 50% of the peak production of a stand-
alone field, and it would be timed to
accommodate the existing Alpine facili-
ties. Production would be drawn out
across a longer timeline. But a satellite
would be the cheaper option.
In a proposed development plan filed
with the U.S. Bureau of Land
Management in early 2018,
ConocoPhillips endorsed a standalone
facility. “The existing processing facility
at Alpine is not feasible for a tie-in of the
Willow development due to geographic
and technical constraints,” the company
wrote. “The Willow master development
plan would require construction of a new
processing facility, the Willow Central
Facility.”
The proposal did, however, envision
using existing pipeline systems to bring
seawater and diesel fuel to the proposed
field and to deliver sales-quality crude
from the field.
The Willow project was delayed earli-
er this year when the U.S. Court of
Appeals for the 9th Circuit extended an
injunction, banning ConocoPhillips from
conducting fieldwork for its Willow oil-
field development. The injunction
emerged from a lawsuit by Sovereign
Inupiat for a Living Arctic and several
environmental organizations against the
Bureau of Land Management. The case
was still pending as The Explorers was
going to print.
Harpoon As work advanced on the Willow
prospect, ConocoPhillips again stepped
westward.
The company’s initial plans for the
2019-20 winter exploration season
included exploration drilling at the
Harpoon prospect, southwest of Willow.
Before the program began, Executive
Vice President of Exploration and
Production Matt Fox said that seismic
work had identified an anomaly worth
investigating. It “looks like there could be
… quite substantial resources,” he said.
“Now it could be gas and it could be
water. It’s almost certainly a reservoir,
because we’re pretty sure that’s what the
seismic signature’s telling us … but it
doesn’t have to be huge for it to be a
tieback to the Willow hub.”
The season was supposed to be among
the largest ever for ConocoPhillips. In
addition to the six Tinmiaq wells, the
company planned four “rank exploration”
wells at Harpoon.
ConocoPhillips hadn’t intended to
complete all 10 wells, only to provide
options for a seven-well program. But
global circumstances made even that
smaller goal impossible.
Just as the exploration season was
gathering momentum, the coronavirus
pandemic was suspending operations
around the world, including the distant
and isolated North Slope.
By the time ConocoPhillips demobi-
lized its fleet in early April in response to
the pandemic, the company had only
completed one of the Harpoon wells —
Harpoon No. 2.
A further disappointment came earlier
this year. In its annual U.S. Security and
Exchange Commission filings,
ConocoPhillips announced that Harpoon
No. 2 had been a dry hole. According to
the company, “evaluations confirmed the
well intersected sub-commercial volumes
of hydrocarbons in the upper Harpoon
interval which will not be developed.”
In an earnings call in early 2020, Fox
said Harpoon 2 appeared to have “clipped
the edge of the topset based on its log
response,” adding that the company
wouldn’t know for sure until it drilled a
second well. Asked by analysts whether
the well had encountered hydrocarbons,
Fox acknowledged that it had. “It looks
from a lithological perspective similar to
other lithological signatures we’re seeing
PETROLEUM NEWS • WEEK OF MAY 16, 2021 5
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The company planned a seven-well exploration program for
2020 but only completed three before reducing its activities in
response to the emerging coronavirus pandemic.
on the edge of these topsets,” he said.
Even so, the company said it still
believed in the potential of the “Harpoon
Complex,” described as Harpoon, Lower
Harpoon and West Harpoon, and intended
to return to it.
Narwhal The 2018 exploration program to
appraise the Willow discovery also includ-
ed a pair of exploration wells just south of
the Colville River unit, near the village of
Nuiqsut.
The play has a long and circular history
with many names.
ConocoPhillips first asked the state to
expand the Colville River unit to include
acreage to the south in 2002, around the
time of its merger. The prospect was
known at the time as Titania. The state
agreed to the Titania expansion but eventu-
ally contracted the acreage out of the unit
in 2004 after ConocoPhillips had failed to
meet its drilling commitments.
A joint venture operated by Brooks
Range Petroleum Corp. subsequently
acquired the acreage through a lease sale
and began referring to the leases as the
Tofkat prospect. The small independent
encountered hydrocarbons on the leases in
early 2008 with the Tofkat No. 1 well and
two related sidetracks and later formed the
Tofkat unit in October 2011.
The state terminated the unit in late
March 2016, after the company missed
work commitments. The termination pro-
ceedings came as ConocoPhillips was
acquiring the acreage. ConocoPhillips
asked the state to incorporate it into the
Colville River unit.
The state was hesitant to approve the
expansion, because of the atypical status of
the leases and because of ConocoPhillips’
previous failure to explore the acreage. But
state officials ultimately agreed to the
request, pursuant to bonds, guarantees and
conditions.
Under this newest effort,
ConocoPhillips began referring to the proj-
ect as Putu. To meet the initial set of con-
ditions required by the state,
ConocoPhillips drilled the Putu No. 2 and
Putu No. 2A wells and made a $3 million
bonus bid replacement. The company also
drilled four appraisal wells — CD4-
595PH1, CD4-595, CD4-594PH1 and
CD4-594 — beyond its work commit-
ments “to better understand the reservoir
and to test the technical feasibility of
extended reach drilling at shallow depth,”
according to the company.
The next round of commitments
required ConocoPhillips to pay $4 million
to the state and submit a plan detailing
efforts to bring the leases into sustained
production.
Based on preliminary testing of its ini-
tial Putu exploration wells, the company
announced the Narwhal discovery, esti-
mated to contain between 100 million and
350 million barrels of oil equivalent. Like
Willow, Narwhal was also in the
Nanushuk formation. Willow and Narwhal
are different sediments deposits within the
formation, with Willow being older.
ConocoPhillips drilled a follow-up well
at Narwhal in the 2019 exploration season.
That summer, the company said that the
results were “encouraging” enough to jus-
tify “an additional unbudgeted horizontal
well from an existing Alpine drill site into
the Narwhal trend” later in the year. That
relatively spontaneous decision, at least by
North Slope standards, reflects one of the
big strategic opportunities of the prospect.
It is close enough to the Colville River unit
to utilize existing well pads, bringing
down costs and reducing some of the most
common logistical complications of off-
road winter exploration.
Asked about the additional well, Fox
said it would be a “long-term test” to better
“understand the long-term deliverability.”
He added, “We also can drill an offset
injection well to this producer from the
same drill site. So, we’re going to take the
opportunity to do that as well. And that
will give us further information on the
Narwhal trend. But it’s really driven by
encouragement and what we saw in the
initial well in the Narwhal, the Putu
appraisal well we call that. We’re feeling
good about that.”
A long-term flow test conducted on the
Narwhal exploration well also “exceeded
expectations,” according to
ConocoPhillips. The well produced at a
peak rate of 4,500 barrels of oil per day,
leading the company to increase its esti-
mated ultimate recovery figure for the
prospect by 150 million to 400 million bar-
rels of oil equivalent.
The company initially envisioned a
two-pronged strategy at the Narwhal
prospect. It would drill about half the wells
horizontally from the existing CD-4 pad at
the Colville River unit and the remaining
wells from a new CD-8 pad in the southern
end of the unit.
Under that proposal, the company ini-
tially expected production as early as 2022
from the wells at the CD-4 pad and pro-
duction from the planned CD-8 pad as
early as 2025.
But by late 2020, the company was
rethinking its approach. The CD4-594 and
CD4-595 appraisal wells had “stretched
the limits” of serviceable extended reach
drilling at shallow depths, according to
ConocoPhillips. And so the company shift-
ed the project toward CD-8, which would
support between 20 and 40 wells, depend-
ing on modeling.
Stony Hill As part of the 2018 program to apprais-
al Putu, ConocoPhillips also explored the
Stony Hill prospect, located in the NPR-A
about six miles south of the village of
Nuiqsut. The well and sidetrack were west
of the Armstrong Energy Inc. wildcat
Horseshoe No. 1 well.
ConocoPhillips described Stony Hill as
a prospect similar to Willow and estimated
that it contained at least 300 million barrels
of recoverable oil in the Nanushuk forma-
tion. In November 2017, ConocoPhillips
executive Matt Fox said the company had
identified “a lot” of Willow lookalikes in
the Nanushuk and “every one of them
we’ve drilled so far has had oil in it, so
we’re hopeful that several of these Willow
lookalikes will deliver.”
The Stony Hill wells encountered oil
but required additional appraisal drilling
and analysis — as did the Putu wells,
which are closer to Colville River unit
infrastructure.
All the ConocoPhillips projects at the
Colville River unit and in the NPR-A place
additional responsibilities on the Alpine
infrastructure. In his Meet Alaska presen-
tation, Isaacson described three projects
6 PETROLEUM NEWS • WEEK OF MAY 16, 2021
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EXPLORERS PREVIEW
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underway this year to expand the gas-han-
dling capacity and power generation and to
add a slug catcher at the Alpine processing
facility. The $190 million projects would
allow Alpine to handle additional produc-
tion coming online.
Nuna Just as the Narwhal project has been
extending the reach of the Colville River
unit to the south, the Nuna project is
extending the reach of the Kuparuk River
unit to the north.
For years, the Nuna prospect was seen
as crucial to the future of the Oooguruk
unit, located in the waters of Harrison Bay
northwest of the Kuparuk River unit.
Companies in the region had known about
the prospect for years. The Nuna field is
located in the shallow Torak formation,
and all drilling into deeper reservoirs had
passed through it.
Pioneer Natural Resources Alaska Inc.
officially discovered the prospect during
the 2013 winter exploration season with its
Nuna No. 2 well. With the results that well,
the independent increased both the aerial
extent and the estimated ultimate recovery
of the field — claiming it could contain
between 75 million and 100 million barrels
of recoverable oil, resulting in some
25,000 barrels of oil per day over 25 to 30
years.
The next operator of Oooguruk, Caelus
Natural Resources Alaska Inc., sanctioned
a $1.4 billion Nuna development — with
$550 million for construction and the
remainder for drilling — in 2015 and even
received a major royalty modification
from the state to make the project work. It
paused work a few years over concerns
about the economic climate.
Caelus ultimately left Alaska in early
2019, selling off its properties. While the
company sold the Oooguruk development
to its minority partner Eni, and later
announced that it had sold 100% owner-
ship in the Nuna leases to its neighbor
ConocoPhillips.
The sale made sense considering that
the company had intended to access the
offshore Nuna leases using an onshore
development at Oliktok Point, in the
Kuparuk River unit.
ConocoPhillips had already been test-
ing wells in the Torok since at least 2013.
Speaking about the project during an earn-
ings call in July 2019, ConocoPhillips
executive Michael Hatfield said that the
Nuna prospect could be developed mostly
from existing pads and roads and that the
remaining facilities could be built in a sin-
gle ice road season. He estimated that the
field could be developed with oil prices in
the low $30 per barrel range and that the
field would produce about 100 million bar-
rels on $100 million investment.
At that time — nine months before the
pandemic — ConocoPhillips was planning
a few years of appraisal as part of it
Kuparuk River program, leading to first oil
in 2022. In his Meet Alaska presentation,
Isaacson put the timeline for first oil at the
“mid-2020s.”
Nuna production would be processed
through Kuparuk River unit facilities, as
would additional production from the
NEWS project. Although not traditional
exploration, the expansion of viscous oil
production from the 1H NEWS drill site is
a source of new oil.
Legacy ConocoPhillips’ work west of Prudhoe
Bay has influenced regional exploration.
Incremental advancement is a defining
feature of the North Slope. The basin con-
tains many known oil fields that would
instantly be standalone commercial prop-
erties if they existed in a less remote corner
of the world. The challenge on the North
Slope over the past 60 years has been
building up regional infrastructure to cre-
ate economies of scale.
By developing the Kuparuk River unit
and then the Colville River unit,
ConocoPhillips changed the characteristics
of the swath of land between those two oil
fields. The so-called “billion-dollar fair-
way” has perpetually interested smaller
exploration companies.
There are currently three units in the
region: the Oil Search-operated Pikka unit,
the Arctic Slope Regional Corp.-operated
Placer unit and the Mustang Holding LLC-
operated Southern Miluveach unit, which
was the first to move into development.
Pikka, Placer and Southern Miluveach
all, in some fashion, rely upon the infra-
structure of the Conoco-Phillips’ operated
units, usually in the form of various
pipeline capacity.
These partnerships are not perfect. In
some cases, smaller players have chosen to
pursue standalone production facilities,
rather than attempt to find space with
ConocoPhillips facilities.
Building standalone facilities greatly
alters the economics of a project. A compa-
ny would only assume the expense volun-
tarily if self-sufficiency provided an equiv-
alent benefit.
But, by comparison, the lands east of
Prudhoe Bay are much less crowded.
Geology is partially responsible for that
imbalance. The Point Thompson unit and
the neighboring Badami unit have both
proven to be exceptionally challenging
puzzles.
But history matters, too.
Point Thompson came online much
later than the Kuparuk River unit. And
whereas the Kuparuk River unit sits imme-
diately adjacent to Prudhoe Bay, Point
Thompson is some 30 miles away, creating
a much larger area to traverse through that
incremental advancement. The reopening
of the NPR-A in 1999 created incentives to
the west, while the political complications
at the Arctic National Wildlife Refuge over
the same time created disincentives to the
east.
One can imagine an alternate history: if
ANWR had been open for development, if
Point Thompson had been closer to
Prudhoe Bay, if geology had been more
accommodating, perhaps there would also
be a billion-dollar fairway to the east
instead of the west. l
PETROLEUM NEWS • WEEK OF MAY 16, 2021 7
RESOURCEBUILDING A
TRIESE INDUS’SALASKA
S
wind and solar generating capacity in
2021 and 2022 will contribute to rising
electricity generation from those
sources and estimates the U.S. electric
power sector added 14.8 gigawatts of
new wind capacity in 2020, with an
additional 15.9 GW expected to come
online in 2021 and an additional 5.2
GW in 2022.
EIA said utility-scale solar will rise
an estimated 10.5 GW in 2020 and is
forecast to grow by 15.7 GW in 2021
and by 15.9 GW in 2022, with about 5
GW of small-scale solar, systems less
than 1 megawatt, expected to come
online in 2021 and again in 2022. l
continued from page 3
EIA OUTLOOK
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The company employed as many as 700 people on the GMT-2
project this winter, which was the third and final year of
construction on the $1.4 billion project.
Contact Eric Lidji at [email protected]
8 PETROLEUM NEWS • WEEK OF MAY 16, 2021
l E X P L O R A T I O N & P R O D U C T I O N
Weekly US rotary rig count up by 8 to 448 By KRISTEN NELSON
Petroleum News
The Baker Hughes U.S. rotary drilling rig count, 448
on May 7, was up by eight from 440 the previous
week and up by 74 from a count of 374 a year ago.
When the count bottomed out at 244 in mid-August
last year, it was not just the low for 2020, but the lowest
the count has been since the Houston based oilfield serv-
ices company began issuing weekly U.S. numbers in
1944.
Prior to 2020, the low was 404 rigs in May 2016. The
count peaked at 4,530 in 1981.
The count was in the low 790s at the beginning of
2020, where it remained through mid-March, when it
began to fall, dropping below what had been the historic
low in early May with a count of 374 and continuing to
drop through the third week of August when it gained
back 10 rigs.
The May 7 count includes 344 rigs targeting oil, up
by two from the previous week and up by 52 from 292 a
year ago, 103 rigs targeting gas, up by seven from the
previous week and up by 23 from 80 a year ago, and one
miscellaneous rig, down by one from the previous week
and down by one from a year ago.
Twenty-three of the holes reported May 7 were direc-
tional, 408 were horizontal and 17 were vertical.
Alaska unchanged from previous week Texas (217) was up by five rigs from the previous
week.
Louisiana (52) was up by three.
Pennsylvania (19) and Utah (9) were each up by one rig.
California (6) was down by a single rig.
Counts in all other states were unchanged from the
previous week: Alaska (3), Colorado (10), New Mexico
(70), North Dakota (15), Ohio (10), Oklahoma (21),
West Virginia (11) and Wyoming (4).
Baker Hughes shows Alaska with three rigs active
May 7, unchanged from the previous week and
unchanged from a year ago, when the state’s count also
stood at three.
The rig count in the Permian, the most active basin in
the country, was up by five from the previous week at
229 and up by 31 from a count of 198 a year ago.
International count down Baker Hughes’ April international rig count of 695,
released May 7, was down 20 rigs from March, with land
rigs down 16 to 530 and offshore rigs down four to 165.
The company said the international count is down
220 from last year’s count of 915, with land rigs down
157 and offshore rigs down 63.
The U.S. rig count for April averaged 436, up 28 from
a March average of 408 and down 130 year-over-year.
In Canada the average count for April was 58, down
51 from a March count of 108 and up 25 year-over-year.
The worldwide count, international plus U.S. and
Canada, was 1,189 in April, down 43 from a March
count of 1,231 and down 325 from 1,514 in April 2020.
The Houston based oilfield services company began
issuing weekly U.S. numbers in 1944 and began issuing
the monthly international rig count in 1975. l
its two Castle North leases; the first NPR-A acreage it plans
to drill.
Borealis’ first taker for a JV partner was Armstrong Oil
& Gas for a 72% interest in the Castle West prospect.
The reason the company decided to drill Castle North
first was because of its proximity to the U.S. Bureau of
Land Management’s Inigok Operations Center and its infra-
structure, which will reduce the costs of the exploration pro-
gram.
The Castle North winter exploration project is on the
Arctic coastal plain approximately 35 miles west of the
Colville River and 15 miles west of Judy Creek. Teshekpuk
Lake is about 30 miles to the north and the closest coastline
is some 40 miles from the project area.
The coastal area is broad and flat with numerous lakes
and waterbodies.
Inigok history The U.S. Geological Survey and Husky Oil drilled the
Inigok No. 1 well in what is today called the Castle North
prospect in 1978 and 1979. The well was subsequently
plugged and abandoned but the infrastructure for the project
remains useable and includes a large gravel pad and a year-
round, 6,500-foot gravel airstrip.
Borealis currently holds two NPR-A leases that define
the Castle North prospect (see map in the pdf and print ver-
sions of this issue of PN).
Drilling plans Drilling operations will involve two wells, Castle North
1 and Castle North 2, although the company has identified
four potential Castle North drilling sites.
Activities include mobilization, snow trail/ice road and
ice pad construction, possible well testing and demobiliza-
tion. They will initially follow the existing exploratory road
from Deadhorse to ConocoPhillips Kuparuk 2-P pad.
Beyond this point, access will require an approximate 80-
mile-long packed snow trail.
Project ice roads will be constructed from the Inigok
Operations Center to transport a drill rig and equipment to
the drill sites. The airstrip at Inigok may be used for addi-
tional access via aircraft, Borealis said.
Drilling operations will occur on a 250,000 square foot
ice pad with a surface working area of 400 feet by 400 feet,
or 160,000 square feet. The pad will support the land-based
drill rig and a small Command Center camp.
Borealis said in its application that the Doyon Arctic Fox
drill rig (or one similar) will be used.
The proposed CN 1 well site is approximately 40 miles
west of the Colville River, 50 miles southwest of Nuiqsut.
Access to the site will be via a 7.4-mile-long ice road
from the Inigok Operations Center, with rig mobilization
expected to occur in January.
Drilling, coring, setting casing, and testing are expected
to take up to 30 days. Once completed, the rig will be demo-
bilized and transported to the next drill site, CN 2, between
late-February and mid-March.
Access to the site will be via a 4.14-mile-long ice road
from the Inigok Operations Center. The rig will be demobi-
lized between mid- and late-April.
Site cleanup, closure inspections and remediation (as
needed) will take place in late-April with final post snow
stick picking and site closure by June, the company said in
its C-plan app.
Ahead of Willow According to Garrard, Nordaq (later rebranded Borealis)
recognized the potential of the Castle trend and obtained
leases in the area three years before ConocoPhillips
announced its big Willow oil discovery.
Borealis said it will use Alaska Chadux as the primary
response action contractor and the IC contractor Witt-
O’Brien’s will provide the primary support for staffing the
incident command team.
Contractors in Deadhorse or Prudhoe Bay may be used
for logistics or other support. l
N A T I O N A L P E T R O L E U M R E S E R V E - A L A S K A ( N P R A ) Nuiqsut
Prudhoe Bay
DS-2P
Inigok
K
NAD 1983 StatePlane Alaska 5 FIPS 5005 Feet
Figure:0 20 4010 Miles
CN 02
CN 04
CN 01CN 03
Delineated Water Source
Delineated Ice Road
Staked Well Pad
Pack Snow Winter Trail
Borealis BLM NPRA Lease
National Petroleum Reserve - Alaska (NPRA) 0 30 6015 Km0.1-1
Beaufort Sea
B E A U F O R T S E A
AA084158AA084157
Oil Discharge Prevention and Cont ingency Plan
BOREALIS ALASKA OIL, INC.CASTLE NORTH
PROSPECT LOCATION MAP
continued from page 1
BOREALIS PERMITTING
PETROLEUM NEWS • WEEK OF MAY 16, 2021 9
Oil Patch Bits
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All of the companies listed above advertise on a regular basis with Petroleum News
Lynden cats make tracks on the Slope As reported by Lynden News May 5, Lynden Oilfield
Services’ fleet of three PistenBully snowcats have been hard at work in Prudhoe Bay this past winter. In an aver-age week, the cats delivered essential supplies to a remote drilling site 145 miles southwest of Deadhorse and hauled a propane truck to refill two remote tanks used to power a weather station. Operators Tony Warner, Joel Martens, James McSharry and Hunter Keogh operate the machines in severe conditions to serve Lynden customers. They received instruction in freight operations and survival as part of their preparation to operate the machines in extreme weather. The PistenBullys give Lynden customers over-snow options to move their cargo including heavy equipment, containers and camps.
CO
URT
ESY
LY
ND
EN
to ensuring adequate safety and environmental protec-
tions for this sensitive ecosystem and Alaska Native sub-
sistence activities.”
Moriarty, president and CEO of the Alaska Oil and Gas
Association, disagreed.
“The 2016 Arctic drilling rule was revised because
much has been learned about operating safely in the Arctic
over the last five years. The 2020 proposed revisions
made substantial improvements over the original rule,
including revisions to incorporate new technologies and
modern drilling practices,” she explained.
“The 2020 rulemaking process also included additional
input from tribal leaders, Alaska Native corporations, and
other stakeholders.”
Interior’s decision “means those enhanced safety and
environmental updates go away, and terms of the 2016
rule remain in place. Ironically, this decision does not ben-
efit the environment as much as the 2020 rule. It is unfor-
tunate that politics have taken over what should have been
a purely scientific exercise,” Moriarty said.
Leah Donahey, Alaska Wilderness League legislative
director, said the 2016 rules incorporated lessons learned
from the 2010 Deepwater Horizon oil spill in the Gulf of
Mexico.
She also said there has not been a public push by com-
panies showing interest in the offshore.
Conservation group Oceana said 37 exploratory wells
have been drilled in the Beaufort and Chukchi seas since
the 1970s; many on leases that have since expired.
Weighed in Russian interest The changes proposed by the Trump administration
were not finalized before Joe Biden was inaugurated. In
November 2020 Interior said the purpose of the proposed
revisions was “to remove unnecessary, burdensome provi-
sions while ensuring that energy exploration on the Arctic
Outer Continental Shelf remains safe and environmentally
responsible.”
“As countries like Russia increase their presence in the
Arctic — including the use of U.S. technologies to devel-
op their seabed resources, it is increasingly important to
ensure that the United States has a strong presence in the
Arctic OCS,” said then-Deputy Secretary of the Interior
Kate MacGregor. “The Beaufort and Chukchi Seas have a
long legacy of oil and gas development — we believe
these proposed revisions will better harness new techno-
logical innovation and best science to allow for responsi-
ble domestic energy development off the coast of Alaska.”
Executive Order 13795, issued by Donald Trump in
2017, directed Interior to review the 2016 Arctic
Exploratory and Drilling Rule and report recommenda-
tions. Interior said the revision team included career sub-
ject matter experts and regulatory specialists who looked
to additional research in the review, including a Bureau of
Safety and Environmental Enforcement-commissioned
technology assessment program study, National
Petroleum Council reports and consultations with “leaders
of more than 23 Alaska Native tribes, Alaska Native
Claims Settlement Act corporations and municipalities
throughout Alaska.”
The Federal Register notice issued for the 2020 revi-
sions said the 2016 rule was a response to BSEE- and
Bureau of Ocean Energy Management-initiated environ-
mental and safety reviews based on experience in the
Arctic OCS “gained from Shell’s 2012 and 2015 Arctic
operations.”
The notice also said the 2016 rule was “narrowly
focused, applying solely to exploratory drilling operations
conducted during the Arctic OCS open-water drilling sea-
son by drilling vessels and ‘jack-up rigs’ in the Beaufort
Sea and Chukchi Sea Planning Areas.”
The BSEE and BOEM review of the 2016 rule takes
into account a congressional declaration in the Outer
Continental Shelf Lands Act that policies and procedures
for managing oil and gas development in the OCS be
“intended to result in expedited exploration and develop-
ment of the Outer Continental Shelf in order to achieve
national economic and energy policy goals, assure nation-
al security, reduce dependence on foreign sources, and
maintain a favorable balance of payments in world trade.”
The bureaus also reviewed new information on techno-
logical developments in an ice environment.
—KAY CASHMAN
(the Associated Press contributed to this story)
continued from page 1
DRILLING RULES“The 2020 rulemaking process also included additional input from tribal leaders, Alaska
Native corporations, and other stakeholders.” —Kara Moriarty
Call 907-250-9769 for details
10 PETROLEUM NEWS • WEEK OF MAY 16, 2021
4011 W. Arctic Blvd., Suite 101 • Anchorage, Alaska
229-6000
the U.S. East Coast.
Colonial is the largest pipeline system for refined oil
products in the United States, capable of moving 3 million
barrels of fuel per day between Texas and New York —
45% of the fuel consumed on the Eastern Seaboard between
the Gulf Coast and the New York metro area.
The snafu, induced by Russia-based hackers, engen-
dered lines of cars as panicked East Coast motorists binged
on whatever fuel supplies could be found at the local gas
station.
“As for this Colonial event, we are paying attention
through trade associations; through government agencies;
through law enforcement; to know what we can learn from
this,” Egan said, adding, “I mean the continually evolving
themes that our team works hard to stay on top of.”
Alyeska is poised to learn whatever it can learn from the
breach, and any other real-world cybercrime that may
plague pipelines and other critical infrastructure, Egan said.
“We learn things and change things because that’s part of
this world of cybersecurity, it’s continually moving … a
very dynamic area,” she said. “I can guarantee that we will
be making changes, but our system is very comprehensive,
and it has served us well.”
Asked about system redundancy, Egan said Alyeska has
multiple layers of protection against cyber threats.
Waivers The Biden Administration began what it called an “all of
government” effort to address the pipeline interruption. It
initiated a survey of Jones Act-qualified vessels to begin the
process of evaluating what assets are available in the Jones
Act fleet to carry petroleum products within the Gulf, and
from the Gulf up the Eastern Seaboard, it said in a May 11
White House fact sheet.
The U.S. Maritime Administration was asked to deter-
mine if there is sufficient capacity on Jones Act-qualified
vessels to carry needed fuel and to determine if a waiver is
warranted, the White House said, adding, “Authority to
receive requests for and to approve waivers to the Jones Act
belongs to the Department of Homeland Security.”
The administration also issued a “targeted, one-week
waiver” allowing multiple states to temporarily use non-
compliant fuel to boost available supply. EPA Administrator
Michael Reagan temporarily waived the federal Reid vapor
pressure requirements for fuel sold in reformulated gasoline
areas of District of Columbia, Maryland, Pennsylvania and
Virginia. The waiver was later extended to a total of 12
affected states, and it was extended to May 31.
“The EPA stands ready to issue waivers for other affect-
ed states expeditiously whenever those requests are
received,” the White House said.
The Department of Transportation issued a separate
order allowing trucks to carry overweight loads of gasoline
and other fuels on highways to move more supply to
Colonial’s customers. It also issued a temporary hours of
service exemption which applies to truckers transporting
gasoline, diesel, jet fuel and other refined petroleum prod-
ucts to the region.
The DOT Federal Motor Carrier Safety Administration
will work closely with its state and industry partners to
monitor driver work hours and conditions for the duration
of the exemption, DOT said.
Colonial said it had, “consistent with our safety policies
and regulatory requirements,” increased aerial patrols of the
pipeline right of way and that it had deployed more than 50
personnel to walk and drive the pipeline each day.
A ransomware group, DarkSide, demanded a cryptocur-
rency ransom valued at millions of dollars, according to
several sources, CNN reported May 12.
But Colonial may not pay up, the report said. Working
with U.S. government officials, Colonial has managed to
retrieve the most important data that was stolen, according
to a source.
“We would like to thank the White House for their lead-
ership and collaboration in resolving this matter as well as
the DOE, PHMSA, FERC and other federal agencies for
their ongoing support,” Colonial said in a May 11 state-
ment.
IBM’s new CEO Arvind Krishna suggested a NASA-
style government investment is required to be able to tackle
cybersecurity.
“When we talk about infrastructure, you talk about the
Colonial Pipeline — that’s physical infrastructure; if the
cyber side gets attacked, the physical is useless,” Krishna
told First Move. “When we talk about infrastructure, we
should make sure the cyber is on equal stage and equal foot-
ing with the physical.”
Krishna called for spending $100 billion on a public/pri-
vate partnership to improve cyber resilience.
“Otherwise, we’ll be victim to these attacks again and
again,” he said.
100% reliability in 2020 Egan said Alyeska achieved 100% TAPS reliability in
2020.
“I think it’s important for people to know that we —
everyone who works here at Alyeska understands how
much the state of Alaska relies on us to be operate reliably,
she said. “We understand how important that is and that’s
why we have such a robust system.”
The first line of defense is people, Egan said.
“People who work here are very connected to TAPS
itself, and take a lot of pride in its operation,” she said.
“We do have drills and exercises, much as we do for
other risks such as oil spills,” she said. “We do test our sys-
tem and then we also test our response, with drills and exer-
cises.”
“We spend a lor of time in our company making sure that
all of our employees and contractors are engaged in and
educated about cybersecurity threat — the ones that you
face at home, the ones that every business faces,” Egan said.
“We also have a very active program in keeping our
employees aware of what they can do to protect themselves,
things like phishing and malware, etcetera.”
Alyeska said 2020 was the first time it had hit the 100%
reliability level since 2003, but that the score is traditionally
above 90%.
“The pipeline is operating reliably throughout this event
with Colonial, and so is our business side of our house,” she
said.
“When we end up in the upper 90s, it’s usually because
of a planned shutdown, and the duration of that shutdown,”
Egan said. “It’s typically not anything concerning, but
some downtime that we planned for in order to get work
done.”
Basically 100% reliability means “every barrel that we
receive we deliver,” Egan said.
“To get down to the nuts and bolts of that and how we
did that last year, we were able to make our maintenance
shutdown several short ones, instead of longer ones,” she
said. “While we might shut down for 12 hours, we use the
tanks at Pump Station 1 to take in incoming crude and when
that shutdown is over, we start moving oil again, so there’s
really no impact on the downstream side.” l
continued from page 1
CYBER-AWARE
Despite a growing string of rebuffs from British
Columbia and federal courts, the threats to TMX have
ranged from COVID-19, rail blockades and legal chal-
lenges to … hummingbirds!
The 3-inch-long birds, whose annual migratory flights
cover round trips of almost 4,000 miles, did what few others
outside of high court rulings have managed to do —
stopped construction of the pipeline through a forest in the
Greater Vancouver region until Aug. 20.
Environment and Climate Change Canada, a federal
department, issued an order in in April covering a strip of
1,100 yards until the end of the bird nesting season.
“Given that it is nesting season, migratory birds are par-
ticularly vulnerable at this time,” the department said, after
two on-site inspections.
“Cutting vegetation and trees or carrying out other dis-
ruptive activities such as bulldozing or using chainsaws in
the vicinity of active nests will likely result in disturbance
or destruction of those nests.”
Trans Mountain, owned by the Canadian government,
confirmed the order without comment.
Insurer issue On a much larger scale, Trans Mountain has been caught
up in a bid by environmentalists to disclose its insurers,
hoping that would provide fresh targets for activists.
That strategy has been spurred by a decision in April by
Zurich, the giant Swiss-based company, not to renew its
coverage of what opponents call a “climate wrecking”
pipeline from the oil sands.
A spokesman for Zurich said the insurer will not com-
ment on its customer dealings.
Trans Mountain said it has the insurance it needs for its
existing operations and the “expansion project” covering
claims up to C$508 million.
Zurich was the sole insurer for the first C$8 million of
potential payouts, along with C$300 million of cover with
other partners.
Lloyd’s of London syndicates are Trans Mountain’s
biggest insurer, with packages that involve 11 companies,
of whom Germany’s Talanx/Hannover indicated last year it
planned to drop its participation in the pipeline, while the
Munich group said it would review its contract given its
new underwriting guideline for the oil sands.
Confidentiality issue As that pressure builds, Trans Mountain gained the
continued from page 1
PIPELINE EXPANSION
see PIPELINE EXPANSION page 11
Contact Steve Sutherlin at [email protected]
PETROLEUM NEWS • WEEK OF MAY 16, 2021 11
Pacific Oil & Gas President Ratnesh Bedi said BP is
among the companies turning to LNG for “sustainable,
stable gas that will supply a clean energy mix” at a time
when the outlook for LNG faces uncertainty.
Work pauses as demand grows In just the last two months, LNG developer Annova
stopped work on its export plant in Brownsville, Texas,
and Pembina Pipeline paused development of its Jordan
Cove project in Oregon.
On the positive side, global LNG demand has
increased every year since 2012, propelled by fast-rising
demand in Asia.
But global LNG buyers have shown some hesitancy
in recent times due to overbuilding of export terminals in
2019 and demand destruction resulting from COVID-19.
BC finances hereditary chiefs While these fluctuations persist, the British
Columbia government has added to the confusion by
financing Wet’suwet’en hereditary chiefs in northwest-
ern B.C. who have tried to sink plans for the C$40 bil-
lion LNG Canada project.
The government of Premier John Horgan has grant-
ed C$7.2 million to the chiefs to promote “unity” in the
fractured First Nation divided between elected and
hereditary leaders, with the bulk of the elected commu-
nities counting on benefits agreements they have
signed with the Shell-operated project.
“British Columbia’s funding announcement to
‘unify’ the Wet’suwet’en nation is the latest in a year-
long series of insults and betrayals of the elected repre-
sentatives of the Wet’suwet’en people,” declared one of
the elected chiefs from five clans Maureen Luggi and
two councilors.
“For nearly a year the (Canadian and B.C. govern-
ments) and the recipients of this funding have been
negotiating in absolute secrecy about communal abo-
riginal rights and title of the Wet’suwet’en people,”
they said.
“We are being removed from any meaningful partic-
ipation in the future of our territory. Despite every
appeal to right and reason, the province has handed
C$7.2 million to an unelected, unrepresentative,
unmandated, unaccountable society to continue their
secret negotiations.”
Some of the new funding will be used to convert
(recently acquired school property) into a
Wet’suwet’en governance center, which is expected to
be a focal point in what the B.C. government says will
allow the divided First Nation to “resolve their own
matters that is central to self-determination.”
This latest twist in a bitter dispute further compli-
cates the outlook for TC Energy’s Coastal GasLink
pipeline to deliver natural gas feedstock to the LNG
Canada liquefaction plant and tanker terminal.
That construction was brought to a halt 16 months
ago by supporters of the hereditary chiefs, when they
blockaded one of Canada’s two main rail lines to the
Pacific Coast, costing governments and companies
hundreds of millions of dollars in lost business. l
continued from page 1
WOODFIBRE LNG
The company told FERC that tidal currents at Turn Point
are known to be powerful and cited an Alaska Power
Authority report from 1981 titled “Angoon Tidal Power and
Comparative Analysis,” which looked at power generation
options which would allow the City of Angoon to replace
on-site diesel generators. Generating electricity from tidal
power in Kootznahoo Inlet was one of the options consid-
ered, but, due to the location’s remoteness, LPS said, “more
accurate assessments of the tidal power resource are not
available.”
“The project concept would be to generate electric
power from a marine hydrokinetic device and store power
in an energy storage system to be used by the City of
Angoon as a supplement to other energy sources,” LPS
said.
The company said a turbine or combination of turbines
generating 300 kilowatts would be appropriate based on
existing power demand in Angoon and allowing for some
growth. Such a turbine would produce some 600-megawatt
hours of electricity in a year.
There would be distribution cables fastened to the
seabed between the turbine generator and the landfall loca-
tion and an energy storage system which would likely
include state-of-the art battery storage technology such as
lithium-ion systems currently used for grid electricity stor-
age.
LPS said it expects that two cables would be installed,
one for primary use and the other for redundancy.
Preliminary studies for the project are estimated at
$50,000.
LPS said lands on Admiralty Island which adjoin the
project area are part of the Kootznoowoo Wilderness. The
company said the project would have no impact on the
wilderness area.
Proposed project In its notice of preliminary permit application FERC said
the proposed project would include:
•A partially buoyant submersed tidal current energy con-
verter with a 3-foot-diameter rotor tethered to an anchor
post driven into the seabed in Kootznahoo Inlet;
•A dual electric cable, each with a capacity of 13.2 kilo-
watts, connecting to on-land storage; and
•On-land storage in the City of Angoon consisting of
individual lithium-ion battery cells.
The application was prepared for LPS by Barrett Energy
Resources Group, which said in a technical memorandum
to FERC that the location of the partially buoyant sub-
merged tidal current energy converter, CEC, would be
marked by a U.S. Coast Guard-approved floating buoy. The
tether would allow the CEC to move with tidal currents to
capture both ebb and flow conditions.
FERC said the project would not connect directly to the
Angoon electric system. The on-land storage system would
have a capacity of 250 kilowatts, FERC said, with annual
average generation not yet determined.
FERC is accepting comments on the permit application
for 60 days from the March 17 application acceptance.
Turnagain Arm project FERC has also accepted a preliminary permit applica-
tion for another, and much larger, Alaska project, the
Turnagain Arm Tidal Electric Generation Project (see story
in March 21 issue of Petroleum News). That application
was accepted on April 28, with a 60-day comment period.
FERC said the proposed project would consist of:
•Six 0.5-mile-long, 300-foot-wide tidal power stations,
five stations containing 40 10-megawatt tidal-to-electrical
energy generating units and one station containing 42 10-
MW tidal-to-electrical energy units; total installed capacity
of 2,420 MW;
•A transmission network of 29.81 miles of undersea
transmission lines connecting the six power stations and
coming onshore at Point Campbell in Anchorage and near
Possession Point on Kenai Peninsula Borough land;
•A 7.5-mile-long aboveground transmission line from
Point Campbell to a control building and step-up facility in
South Anchorage;
•A 2.91-mile-long, 130-kilovolt aboveground transmis-
sion line from the Anchorage control building to a 40,000-
square-foot industrial battery array with a storage capacity
of 300 MW and then to the Chugach Electric Association
substation in Anchorage;
•A 0.2-mile-long, 230 kV aboveground transmission line
from the control building to a 200,000-square-foot hydro-
gen electrolysis plant and storage yard in South Anchorage
with a processing capacity of up to 1.2-gigawatts;
•A 34.8-mile aboveground transmission line from Point
Possession to a control building and step-up facility in
Nikiski;
•A 2.75-mile-long, 230 kV aboveground transmission
line from the Nikiski control building to the Homer Electric
Association substation; and
•Appurtenant facilities.
The proposed project would have an estimated average
annual general of 10,599,500 megawatt hours.
—KRISTEN NELSON
continued from page 1
ANGOON TIDAL
support of the Canada Energy Regulator to
keep its insurers’ names confidential.
The federal agency said Trans Mountain
had “satisfied the requirements for confi-
dentiality. The names of Trans Mountain’s
insurers could reasonably be expected to
prejudice its competitive position in its deal-
ing with potential insurers.”
Charlene Alecks, a spokesperson for the
Tsleil-Waututh Nation Sacred Trust
Initiative, one of the Indigenous opponents
of the pipeline, said the CER is “expanding
Trans Mountain’s culture of secrecy when it
should be doing the opposite, especially for
a government-owned company during a cli-
mate crisis. This is a dangerous precedent.”
Grand Chief Stewart Phillip, president of
the Union of British Columbia Indian
Chiefs, said any company insuring Trans
Mountain is “complicit in violations of
Indigenous rights, because the proposed
pipeline expansion does not have the con-
sent of all impacted First Nations along the
route.”
Elana Sulakshana, energy finance cam-
paigner for Rainforest Action Network, said
Zurich’s action “demonstrates that it is wak-
ing up to the risks of this toxic project in
Indigenous land rights, local ecosystems
and the planet.”
She said some of Zurich’s peers in the
global insurance industry “are also taking
note, as eight (of the 11 companies) now
have policies that limit or end insurance
coverage (for the oil sands).”
The opponents of the pipeline are now
calling on the insurers to turn down invita-
tions to renew their coverage; rule out insur-
ance for all oil sands extraction and trans-
portation; and adopt policies to ensure that
projects and companies they insure have
obtained the full, informed consent of
impacted communities.
Financial impact Further stoking the fires of opposition,
Simon Fraser University in the Greater
Vancouver region issued a new benefit-cost
analysis study estimating Canada stands to
lose between C$3.2 billion and C$18.45 bil-
lion from the pipeline expansion.
University researchers examined close
to 20 business scenarios involving sales of
TMX crude and concluded than none will
generate a net benefit for Canada, pointing
to the prospects of increased construction
costs, the effects of weaker oil prices,
Canada’s new climate plan and the cancel-
lation of Keystone XL permits by President
Joe Biden.
Lead author and an SFU professor,
Thomas Gunton, said climate policies have
affected the landscape significantly since
the Canadian government bought Trans
Mountain off Kinder Morgan for C$4.5 bil-
lion in 2018.
The study said the crux of the problems
facing Trans Mountain is oil demand, which
it claimed will decline over coming years
because of global policy shifts toward net-
zero greenhouse gas emission goals, con-
trary to many predictions that consumption
of fossil fuels will remain strong until at
least 2050.
—GARY PARK
continued from page 10
PIPELINE EXPANSION
To advertise in Petroleum News, contact Susan Crane
at 907.250.9769petroleumnews.com
In preparation for the system restart,
Colonial Pipeline has taken delivery of an
additional 2 million barrels of fuel from
refineries for deployment upon restart, the
company said in a May 11 situation update.
ANS fell behind Brent May 10 in the
race to $70, plunging $1.41 to $67 after
closing 12 cents above Brent on May 7.
Brent edged up May 10 by 4 cents to
$68.32, while WTI rose 2 cents to $64.92.
All three of the indexes moved modestly
higher on May 11.
U.S. crude exports fell for the week end-
ing May 7 to 1.8 million barrels per day, the
lowest level since October 2018, while
crude inventories were 0.4 million barrels
lower, according to the U.S. Energy
Information Administration.
The combination of lower exports and a
crude draw is considered by analysts to be
bullish for prices.
Demand to outstrip supply Demand levels that outstrip supply in the
second half of 2021 may pull oil prices
higher.
Under the current Organization of the
Oil Exporting Countries production sce-
nario, supplies won’t rise fast enough to
keep pace with expected demand recovery,
the International Energy Agency said in its
May Oil Market Report.
As vaccination rates rise and mobility
restrictions ease, global oil demand is set to
soar from 93.1 million bpd in first quarter
2021 to 99.6 million bpd by year-end, the
IEA said.
Weaker-than-expected first quarter oil
use in the United States and Europe and a
reduced outlook for India due to its
COVID-19 surge led the agency cut its out-
look for 2021 demand growth to 5.4 million
bpd, 270,000 bpd lower than in its previous
report.
The forecast for the second half is large-
ly unchanged on the assumption that the sit-
uation in India and elsewhere improves, the
IEA said.
World oil supply rose 330,000 bpd to
93.4 million bpd in April and will increase
further in May as OPEC+ continues to ease
output cuts, the agency said. Based on the
current OPEC+ agreement, global oil pro-
duction is set to grow by 3.8 million bpd
from April to December.
For 2021, world oil production is set to
rise by 1.4 million bpd year-on-year versus
a collapse of 6.6 million bpd in 2020, the
IEA said.
Canada leads non-OPEC+ producers
with growth of 340,000 bpd while the US is
set to contract by an additional 160,000 bpd,
it said.
The IEA revised its estimates of 2021
global refinery throughput on demand
downgrades, newly announced temporary
and permanent shutdowns, and in anticipa-
tion of a strong hurricane season in the
United States.
“As downward revisions mostly affected
2Q21, we maintain our forecast of a strong
ramp-up in refining activity in the next four
months, with refinery runs expected to peak
in August,” the IEA said, adding that after a
7.4 million bpd decline in 2020, refinery
intake is expected to increase by 4 million
bpd in 2021.
OPEC cautiously optimistic for 2nd half The global economic recovery seems to
be gaining momentum at a diverging pace
OPEC said in its Monthly Oil Market
Report for May.
“Those economies that are able to grad-
ually contain the pandemic, thanks to vacci-
nation campaigns and other successful con-
tainment strategies, and that also have the
financial capabilities to provide economic
stimulus measures are rebounding quickly,”
the cartel said.
OPEC expects most of the global recov-
ery to materialize later in the year, but it
cautioned that there are still some signifi-
cant uncertainties.
“The path of the COVID-19 pandemic
will be the overarching factor impacting the
near-term pace of the recovery, with the
potential emergence of further harmful
COVID-19 variants posing a particular
risk,” OPEC said. “Moreover, sovereign
debt in most economies has risen to levels at
which a lift in interest rates could cause
severe fiscal strain.”
A further rise in inflation, especially in
the United States and the Euro-zone, may
cause some tightening of monetary policies,
which will need to be watched in the short
term, OPEC said, adding that trade-related
disputes, especially between the U.S. and
China, may continue.
For 2021, OPEC expects world oil
demand is to increase by 6.0 million bpd,
unchanged from last month’s estimate, to
average 96.5 million bpd.
—STEVE SUTHERLIN
continued from page 1
OIL PRICES
12 PETROLEUM NEWS • WEEK OF MAY 16, 2021
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